Method for determining drainage gas recovery process of gas well

Abstract

The invention belongs to the technical field of oil-gas field development, and relates to a gas well drainage gas recovery process determination method. Aiming at the problems that a traditional method depends on experience judgment, is short of quantitative analysis and is difficult to accurately evaluate the process applicability and effect and the like, the method comprises the following steps: collecting underground tubular columns and production data of a gas well, and calculating parameters such as apparent velocity and density of gas phase and liquid phase; drawing an inflow / outflow dynamic curve, and judging whether the gas well can produce stably or not; performance analysis is carried out on the optimized pipe column process, the well mouth pressurization process, the gas lift process, the foam drainage process and the plunger process, the lower action limit of each process is determined, and quantization parameters are unified; finally, a scoring and weighting system is customized, scores are obtained through a drainage gas production comprehensive decision model, and the process with the highest score is the optimal process. Compared with an existing method, the method has the advantages that the scientificity and accuracy of process selection are improved, the gas well exploitation efficiency and economic benefits are improved, and the cost is reduced.

Description

Technical Field

[0001] The invention belongs to the technical field of oil and gas field development, and mainly relates to a method for determining a gas well drainage and gas production process. Background Art

[0002] In the field of oil and gas field development, the reasonable selection of gas well drainage and gas production technology is crucial to the efficient production of gas wells; with the continuous development of natural gas resources, gas wells generally face the problem of liquid accumulation in the production process, which seriously affects the output and production stability of gas wells; different gas wells have differences in geological conditions, wellbore structure and fluid properties, and the applicable drainage and gas production technology is also different.

[0003] Traditional methods for selecting drainage gas production processes often rely on empirical judgment and lack systematic quantitative analysis. This method is difficult to accurately evaluate the applicability and effectiveness of different processes when faced with complex gas well production conditions. In some gas wells, due to insufficient understanding of the relationship between formation energy and wellbore flow characteristics, the selected drainage gas production process cannot function effectively, which not only fails to increase gas well production, but may also increase production costs and operational difficulty.

[0004] The invention patent (CN106570273A) established a three-dimensional model of daily gas production, water-gas ratio and well depth by optimizing the calculation model of the critical liquid-carrying flow rate of natural gas. According to the production parameters such as daily gas production, water-gas ratio and well depth of the gas well, the drainage gas production process of the gas well can be simply and quickly determined. The weight system determination method in the patent model is not detailed enough and the calculation consideration of economic benefits is not comprehensive enough; the invention patent (CN115221666A) comprehensively considers the production limit applicable to the pressure and the production limit applicable to the liquid, quantitatively determines the applicable limit of the drainage gas production process, and quantitatively determines the drainage gas production process, but it is mainly aimed at conventional gas-bearing wells, and does not comprehensively consider some special gas wells; the invention patent (CN117905419A) provides a process selection based on the distribution of liquid accumulation in the wellbore. Selection method and system, by establishing a drainage gas production process model, the best drainage gas production process measures can be quickly selected. The patent divides liquid level depth, well inclination, drainage volume and gas-liquid ratio into limited levels, but the actual gas well conditions are complex and changeable. This simple classification may not accurately cover all well conditions, and it is difficult to determine the most suitable process, resulting in inaccurate process selection; at present, although there are some studies on gas well production technology, the comprehensive quantitative determination method for drainage gas production technology still needs to be improved; some studies only focus on the improvement of a single process or its application under specific working conditions, and fail to consider the comprehensive comparison and scientific selection of multiple processes under different gas well conditions as a whole; this makes the decision on gas well drainage gas production technology lack scientific basis in actual production, and it is difficult to maximize the production efficiency of gas wells.

[0005] To this end, the present invention is committed to proposing a method for determining the gas well drainage and gas production technology based on quantitative analysis. By systematically collecting gas well data, establishing an accurate model and a comprehensive quantitative evaluation system, it provides strong support for the reasonable selection of gas well drainage and gas production technology, thereby improving the production efficiency and economic benefits of the gas well. Summary of the invention

[0006] The present invention aims to provide a method for determining the drainage gas production process of a gas well, which quantitatively analyzes the key indicators of different processes through unified quantitative parameters, uses a weighted scoring system to achieve scientific determination of the process, and provides a theoretical basis for determining the drainage gas production process.

[0007] In order to achieve the above-mentioned object, a method for determining a gas well drainage and gas production process according to the present invention comprises the following steps: Step S1: Collect the downhole pipe string data and production data of the gas well, including wellbore structure, well inclination angle θ, pipe diameter D, gas-liquid ratio GLR, oil pressure p t , wellhead temperature T 0 , natural gas physical parameters, gas production index J, current formation pressure P r , gas phase relative density γ g and liquid relative density γ L ; Calculate the gas phase apparent velocity and the liquid phase apparent velocity.

[0008] Step S2: draw the inflow / outflow dynamic curve under the current production conditions; use the gas well productivity empirical formula commonly used in engineering to calculate the gas well productivity under each process, and then use the friction coefficient in the Mukherjee-Brill model to calculate the wellbore pressure drop; based on all the data collected in step S1, a series of gas production is given, the corresponding bottom hole flow pressure is calculated, and the outflow curve of the bottom hole flow pressure changing with the gas production is obtained; given a series of bottom hole flow pressures, the corresponding gas production is calculated, and the inflow curve of the gas production changing with the bottom hole flow pressure is obtained; determine whether the inflow / outflow curves intersect, if there is an intersection, it indicates that stable production is currently possible, otherwise it cannot be stably produced; further, through all the data collected in step S1, the gas well productivity empirical formula commonly used in engineering is used to calculate the gas well productivity, and the Mukherjee-Brill model is used to calculate the wellbore pressure drop.

[0009] Step S3: Perform performance analysis on the preferred tubing, wellhead pressurization and gas lift process; further, for the preferred tubing measures, according to the calculation formula in step S2, by changing the inner diameter of the tubing, a series of gas production is given, and the corresponding bottom hole flow pressure is calculated to obtain the outflow curve of the bottom hole flow pressure corresponding to the gas production. Under the condition that the gas production index remains unchanged, the formation pressure is reduced based on the current formation pressure, and P is set. rTO1 Equal to the current formation pressure P r , given a series of formation pressures P rTO1To P rTO , calculate the inflow curve of gas production changing with bottom hole pressure under different formation pressure conditions; find the gas production value corresponding to the intersection of the inflow curve and the outflow curve under different formation pressure conditions, the gas production at the intersection is the gas production of the gas well under the corresponding formation pressure of the optimal string technology, if there is no intersection, the gas production is considered to be 0; further draw the curve of the change of the intersection gas production with the formation pressure, the minimum gas production corresponding to the optimal string technology is q gminTO The maximum gas production corresponding to the optimal column process is q gmaxTO The maximum formation pressure when the gas production is 0 is the formation pressure corresponding to when the inflow and outflow curves are just tangent, which is also the lower limit of the applicable formation pressure P for the optimal string technology. rminTO ; For the wellhead pressurization process, according to the calculation formula in step S2, by reducing the wellhead oil pressure to the inlet pressure of the compressor, a series of gas production is given, and the corresponding bottom hole flow pressure is calculated to obtain the outflow curve of the bottom hole flow pressure corresponding to the gas production. Under the condition that the gas production index remains unchanged, the formation pressure is reduced based on the current formation pressure, and P is set. rCO1 Equal to the current formation pressure P r , given a series of formation pressures P rCO1 To P rCO , get the inflow curve of gas production changing with bottom hole pressure under different formation pressure conditions; find the gas production value corresponding to the intersection of the inflow curve and the outflow curve under different formation pressure conditions. The gas production at the intersection is the gas production of the gas well under the corresponding formation pressure by the wellhead boosting process. The minimum gas production corresponding to the wellhead boosting process is q gminCO , the maximum gas production corresponding to the wellhead pressurization process is q gmaxCO If there is no intersection, the gas production is considered to be 0; further draw the curve of the intersection gas production and formation pressure. The maximum formation pressure when the gas production is 0 is the formation pressure corresponding to the inflow and outflow curves just tangent to each other, which is also the lower limit of the effective formation pressure P of the wellhead boosting process. rminCO ; For the gas lift process, according to the calculation formula in step S2, a series of gas production is given and the gas injection volume of the gas lift is added respectively. The liquid production is calculated according to the gas-liquid ratio GLR provided in step S1 and the given gas production, so as to calculate the corresponding bottom hole flow pressure, and obtain the outflow curve of the bottom hole flow pressure corresponding to the change of gas production. Under the condition of ensuring that the gas production index remains unchanged, the formation pressure is reduced based on the current formation pressure, and P is set. rGL1 Equal to the current formation pressure P r , given a series of formation pressures P rGL1 To P rGL, get the inflow curve of gas production changing with bottom hole pressure under different formation pressure conditions; find the gas production value corresponding to the intersection of the inflow curve and the outflow curve under different formation pressure conditions. The gas production at the intersection is the gas production of the gas well under the corresponding formation pressure of the gas lift process. The minimum gas production corresponding to the gas lift process is q gminGL , the maximum gas production corresponding to the gas lift process is q gmaxGL If there is no intersection, the gas production is considered to be 0; further draw the curve of the intersection gas production and formation pressure. The maximum formation pressure when the gas production is 0 is the formation pressure corresponding to the inflow and outflow curves being just tangent, which is also the lower limit of the applicable formation pressure P of the gas lift process. rminGL .

[0010] Step S4: For the foaming process, given a series of gas production and the concentration coefficient x of the foaming agent, the bottom hole flow pressure is calculated; then the critical velocity of gas-liquid two-phase liquid film reversal and the critical velocity of foam film reversal are calculated by changing the foaming agent concentration; further, based on the calculated bottom hole flow pressure, the outflow curve of the bottom hole flow pressure of the foaming well corresponding to the change of gas production can be obtained, and under the condition that the gas production index remains unchanged, the formation pressure is reduced based on the current formation pressure, and P is set. rFL1 Equal to the current formation pressure P r , given a series of formation pressures P rFL1 To P rFL , get the inflow curve of gas production changing with bottom hole pressure under different formation pressure conditions; find the gas production value corresponding to the intersection of the inflow curve and the outflow curve under different formation pressure conditions. The gas production at the intersection is the gas production of the gas well under the corresponding formation pressure of the bubble drainage process. The minimum gas production corresponding to the bubble drainage process is q gminFL The maximum gas production corresponding to the bubble discharge process is q gmaxFL If there is no intersection, the gas production is considered to be 0; further draw the curve of the intersection gas production and formation pressure. The maximum formation pressure when the gas production is 0 is the formation pressure corresponding to the inflow and outflow curves just tangent to each other, which is also the lower limit of the applicable formation pressure P of the bubble drainage process. rminFD .

[0011] Step S5: For the plunger gas lift process, the minimum gas production applicable to the given plunger process is q gminPL According to the inflow / outflow curve drawn in step S2, keep the gas production index J unchanged, increase or decrease the formation pressure and draw the inflow curve under the formation pressure condition, so that the inflow curve is tangent to the outflow curve, connect the tangent point and the coordinate origin to obtain a straight line L, take the current formation pressure as the reference, reduce the formation pressure, and let P rPL1 Equal to the current formation pressure P r , given a series of formation pressures P rPL1 To P rPL, get the inflow curve of gas production changing with bottom hole pressure under different formation pressure conditions, find out the gas production value corresponding to the intersection of the inflow curve and the straight line L under different formation pressure conditions; the gas production at the intersection of the inflow curve and the straight line L under the current formation pressure condition is the maximum gas production q corresponding to the plunger gas lift process gmaxPL The formation pressure corresponding to the lower limit of the applicable gas production of the given plunger process is the lower limit of the applicable formation pressure of the plunger process P rminPL .

[0012] Step S6: normalize different processes to the inflow / outflow dynamic curve with the optimal process conditions, obtain the operating output of each process under different formation pressure conditions, and then make a unified comparison; further, the maximum gas production obtained from the inflow / outflow dynamic curve of each process in steps S3 to S5, the lower limit of the formation pressure corresponding to each process, and the minimum gas production after adopting each process; calculate the gas production area S, the formation pressure range Δp r That is, the difference between the current formation pressure and the lower limit of the applicable pressure of each process, and the gas production range Δq g It is the difference between the maximum gas production and the minimum gas production of each process. The gas production decreases under unit formation pressure. , gas production area per unit formation pressure .

[0013] Step S7: Customize the scoring system and weighting system according to the set comparison process, including the optimal tubing string, wellhead pressurization, gas lift, bubble drainage, and plunger; Furthermore, the expression of the comprehensive decision-making model for drainage and gas production is: Where, M is the comprehensive decision-making score of drainage and gas production, points; η is the technical score of the process, points; λ is the economic score of the process, points; k is the weight of the technical score, dimensionless; The first-level indicators are divided into technical part and economic part, with the weight of the technical part being 0.6 and the weight of the economic part being 0.4. The second-level indicators in the technical part are the maximum gas production and the formation pressure range Δp r , gas production decreases under unit formation pressure , gas production area S, gas production area per unit formation pressure , the lower limit of formation pressure, with weights of 0.8, 0.8, 1, 1, 1, 1 respectively. The secondary indicators in the economic part are one-time investment and annual maintenance cost, with weights of 0.5 and 0.5 respectively. Then, according to the parameters obtained in step S6, weighted calculation and normalization are performed to finally obtain a score, and the process with the highest score is defined as the optimal process.

[0014] The present invention provides a systematic and comprehensive method for determining the drainage gas production process, which comprehensively considers technical and economic factors and improves the scientificity and accuracy of process selection; by quantitatively analyzing the performance indicators of different processes, the advantages and disadvantages of various processes under different production conditions can be intuitively compared, providing a reliable basis for on-site operations; the establishment of a weighted scoring system makes the process determination process more objective and reasonable, which helps to improve the production efficiency and economic benefits of gas wells and reduce production costs. BRIEF DESCRIPTION OF THE DRAWINGS

[0015] Figure 1 is a process flow chart; Figure 2 Schematic diagram of the process for optimizing the tubing column; Figure 3 It is a schematic diagram of the supercharging process; Figure 4 This is a schematic diagram of the gas lift process; Figure 5 Schematic diagram of the foaming process; Figure 6 Schematic diagram of the plunger process. DETAILED DESCRIPTION

[0016] In order to make the purpose and calculation process of the present invention clearer, the present invention is further described in detail below in conjunction with the accompanying drawings to highlight the advantages of the present invention; like Figure 1 As shown, Figure 1 The process determination flow chart of the present invention provides a method for determining the gas well drainage gas production process; firstly, the downhole pipe string data and production data of the gas well are collected, including the wellbore structure, well inclination angle θ, pipe diameter D, gas-liquid ratio GLR, oil pressure p t , wellhead temperature T 0 , natural gas physical parameters, gas production index J, current formation pressure P r , gas phase relative density γ g and liquid relative density γ L ; Then calculate the gas phase apparent velocity, liquid phase apparent velocity, gas phase density, liquid phase density, use the Mukherjee-Brill model to calculate the bottom hole flow pressure, the bubble well bore pressure drop model based on the drift model to calculate the bottom hole flow pressure, and calculate the well bore pressure drop after the plunger process, and draw the inflow / outflow dynamic curves after the implementation of each process, and obtain the maximum gas production and the lower limit of the formation pressure corresponding to each process; calculate the gas production area S and the formation pressure range Δp r That is, the difference between the current formation pressure and the lower limit of the applicable pressure of each process, and the gas production range Δq g It is the difference between the maximum gas production and the minimum gas production of each process. The gas production decreases under unit formation pressure. , gas production area per unit formation pressure , and finally conduct a unified quantitative analysis, give each process a weighted score, and determine the process with the highest score.

[0017] (1) The expression of gas phase superficial velocity is: (1); The expression of liquid superficial velocity is: (2); Where D is the pipe diameter, m; Q g is the gas well production, m 3 / d;Q l is the liquid production, m 3 / s; B g is the volume coefficient, dimensionless; The expression of volume coefficient is: (3); The expressions of gas and liquid phase density are: (4); (5); In the formula, ρ g , l is the density of gas and liquid phase, kg / m 3 ; p is pressure, MPa; γ g is the relative density of the gas phase, dimensionless, taken as 0.65; γ L is the relative density of the liquid phase, dimensionless, taken as 1.02; Z g is the natural gas deviation coefficient, dimensionless, taken as 0.94; T is the temperature, K.

[0018] (2) Draw the inflow / outflow dynamic curve under current production conditions; The gas well productivity under each process is calculated by using the empirical formula of gas well productivity commonly used in engineering, and then the friction coefficient in the Mukherjee-Brill model is used to calculate the wellbore pressure drop; based on all the data collected in step S1, a series of gas production is given, the corresponding bottom hole flow pressure is calculated, and the outflow curve of the bottom hole flow pressure changing with the gas production is obtained; a series of bottom hole flow pressures are given, the corresponding gas production is calculated, and the inflow curve of the gas production changing with the bottom hole flow pressure is obtained; it is determined whether the inflow / outflow curves intersect, if there is an intersection, it indicates that stable production is currently possible; otherwise, stable production cannot be achieved; Furthermore, based on all the data collected in step S1, an empirical formula for gas well productivity commonly used in engineering is selected: (6); Where, J is the gas production index, m 3 / (d·MPa 2 );pr is the average formation pressure, MPa; p wf is the bottom hole flowing pressure, MPa; The wellbore pressure drop model expression is: (7); Where z is the depth, m; ρ m is the mixed density, kg / m 3 ; g is the acceleration due to gravity, m / s 2 ; θ is the well inclination angle, °; f is the friction coefficient, dimensionless; v m is the superficial velocity of the gas-liquid mixture, m / s; The expression of the superficial velocity of gas-liquid mixture is: (8); In the formula, v SG is the superficial gas velocity, m / s; v SL is the apparent liquid velocity, m / s; The mixed density is a function of the liquid holdup and is expressed as: (9); In the formula, H L is the liquid holdup rate, %;ρ L is the liquid density, kg / m 3 ρ G is the gas density, kg / m 3 ; Liquid holdup H L The model calculation expression is: (10); The friction coefficient f is calculated using the Mukherjee-Brill model: (11); Where, e is the absolute roughness, m; N Re is the no-slip Reynolds number, dimensionless, and its expression is: (12); In the formula, ρ ns is the density of the mixture without slippage, kg / m 3 ;μ ns is the viscosity of the no-slip mixture, Pa·s.

[0019] (3) Conduct performance analysis on the optimal tubing string, wellhead pressurization and gas lift technology; Furthermore, for the optimization of the tubing string, according to the calculation formula in step S2, by changing the inner diameter of the tubing, a series of gas production is given, the corresponding bottom hole flow pressure is calculated, and the outflow curve of the bottom hole flow pressure corresponding to the change of gas production is obtained. Under the condition that the gas production index remains unchanged, the formation pressure is reduced based on the current formation pressure, and P is set. rTO1 Equal to the current formation pressure P r , given a series of formation pressures P rTO1 To P rTO , the inflow curve of gas production changing with bottom hole pressure under different formation pressure conditions is calculated; Figure 2 As shown in the figure, find the gas production value corresponding to the intersection of the inflow curve and the outflow curve under different formation pressure conditions. The gas production at the intersection is the gas production of the gas well under the corresponding formation pressure of the optimal string process. If there is no intersection, the gas production is considered to be 0. Further draw the curve of the intersection gas production changing with the formation pressure. The minimum gas production corresponding to the optimal string process is q gminTO The maximum gas production corresponding to the optimal column process is q gmaxTO The maximum formation pressure when the gas production is 0 is the formation pressure corresponding to when the inflow and outflow curves are just tangent, which is also the lower limit of the applicable formation pressure P for the optimal string technology. rminTO ; For the wellhead pressurization process, according to the calculation formula in step S2, by reducing the wellhead oil pressure to the inlet pressure of the compressor, a series of gas production is given, and the corresponding bottom hole flow pressure is calculated to obtain the outflow curve of the bottom hole flow pressure corresponding to the gas production. Under the condition that the gas production index remains unchanged, the formation pressure is reduced based on the current formation pressure, and P is set. rCO1 Equal to the current formation pressure P r , given a series of formation pressures P rCO1 To P rCO , we can get the inflow curve of gas production changing with bottom hole pressure under different formation pressure conditions; Figure 3 As shown in the figure, find the gas production value corresponding to the intersection of the inflow curve and the outflow curve under different formation pressure conditions. The gas production at the intersection is the gas production of the gas well under the corresponding formation pressure by the wellhead boosting process. The minimum gas production corresponding to the wellhead boosting process is q gminCO , the maximum gas production corresponding to the wellhead pressurization process is q gmaxCO If there is no intersection, the gas production is considered to be 0; further draw the curve of the intersection gas production and formation pressure. The maximum formation pressure when the gas production is 0 is the formation pressure corresponding to the inflow and outflow curves just tangent to each other, which is also the lower limit of the effective formation pressure P of the wellhead boosting process. rminCO ; For the gas lift process, according to the calculation formula in step S2, a series of gas production is given and the gas injection volume of the gas lift is added respectively. The liquid production is calculated according to the gas-liquid ratio GLR provided in step S1 and the given gas production, so as to calculate the corresponding bottom hole flow pressure, and obtain the outflow curve of the bottom hole flow pressure corresponding to the change of gas production. Under the condition of ensuring that the gas production index remains unchanged, the formation pressure is reduced based on the current formation pressure, and P is set. rGL1 Equal to the current formation pressure P r , given a series of formation pressures P rGL1 To P rGL , we can get the inflow curve of gas production changing with bottom hole pressure under different formation pressure conditions; Figure 4 As shown in the figure, find the gas production value corresponding to the intersection of the inflow curve and the outflow curve under different formation pressure conditions. The gas production at the intersection is the gas production of the gas well under the corresponding formation pressure of the gas lift process. The minimum gas production corresponding to the gas lift process is q gminGL , the maximum gas production corresponding to the gas lift process is q gmaxGL If there is no intersection, the gas production is considered to be 0; further draw the curve of the intersection gas production and formation pressure. The maximum formation pressure when the gas production is 0 is the formation pressure corresponding to the inflow and outflow curves being just tangent, which is also the lower limit of the applicable formation pressure P of the gas lift process. rminGL .

[0020] (4) For the foaming process, given a series of gas production and foaming agent concentration coefficient x, calculate the bottom hole flowing pressure; Furthermore, the calculation expression of the bottom hole pressure of the bubble well is: (13); In the formula, f m is the gas-liquid two-phase friction coefficient in the Mukherjee-Brill model, dimensionless; x is the foaming agent concentration coefficient, dimensionless; v cfoam is the critical air velocity of foam film reversal, m / s; a 1 、a 2 、a 3 、a 4 represents the coefficients of the polynomial obtained by experimental fitting; The gas-liquid mixture density expression is: (14); Where, α is the gas content, %; The implicit equation for calculating the gas content α in the wellbore is: (15); Where Δρ is the difference between gas and liquid density, kg / m 3 ; The Reynolds number calculation formula is: (16); The surface tension calculation formula is: (17); Where Re is the Reynolds number, dimensionless; σ is the surface tension, mN / m, μ m is the dynamic viscosity, Pa·s; The specific solution process is: 1) Input known parameters: pipe diameter D, oil pressure pt, gas flow rate v SG , liquid flow rate v SL , pipeline inclination angle θ, foaming agent concentration C v ; 2) Select an appropriate calculation step length ΔL and divide the pipe section into n sections; 3) Assuming the gas content α est ; 4) Calculate the mixed Reynolds number Re by formula (16), and calculate the surface tension σ by formula (17); 5) Reynolds number Re, gas-liquid flow rate v SG With v SL , gas-liquid density ρ g and ρ l , inclination angle θ, and surface tension σ are substituted into formula (15) and the gas void fraction is calculated using the Newton iteration method, that is, α cal =α est -f(α est ) / f'(α est ), where f(α est ) is the gas content calculated in the last cycle, f'(α est ) is the rate of change of the calculated gas holdup after the last cycle with the assumed gas holdup, i.e., Δα cal / Δα est ; Set α est With α cal For comparison, if |α cal -α est | / α cal <0.001, the accuracy requirement is met, and the gas content α is output cal , otherwise α cal The value of α is assigned to est , repeat step 4) to step 5) until the accuracy requirement is met; 6) Calculate the pressure drop gradient dp / dz of the micro-element segment by formula (13); 7) Calculate the pressure change Δp of the micro-element segment cal =(dp / dz)ΔL; 8) Set the pressure p at the outlet of the current cycle step t +1=p t +Δp calAs the input parameter of the next calculation unit, repeat the above steps until the calculation is completed; The expression of foaming agent concentration coefficient is: (18); In the formula, C v is the concentration of foaming agent, mg / L; CMC is the critical micelle concentration of foaming agent, mg / L; The expression of the critical velocity of gas-liquid two-phase liquid film reversal is: (19); In the formula, v cf is the critical velocity of gas-liquid two-phase liquid film reversal, m / s; c 1 、c 2 represents the coefficients of the polynomial obtained by experimental fitting; The expression of critical air velocity for foam film reversal is: (20); Where b 1 、b 2 、b 3 represents the coefficients of the polynomial obtained by experimental fitting; Based on the calculated bottom hole flow pressure, the outflow curve of the bottom hole flow pressure of the bubble well with the corresponding change of gas production can be obtained. Under the condition of ensuring that the gas production index remains unchanged, the formation pressure is reduced based on the current formation pressure, and P rFL1 Equal to the current formation pressure P r , given a series of formation pressures P rFL1 To P rFL , we can get the inflow curve of gas production changing with bottom hole pressure under different formation pressure conditions; Figure 5 As shown in the figure, find the gas production value corresponding to the intersection of the inflow curve and the outflow curve under different formation pressure conditions. The gas production at the intersection is the gas production of the gas well under the corresponding formation pressure of the bubble drainage process. The minimum gas production corresponding to the bubble drainage process is q gminFL The maximum gas production corresponding to the bubble discharge process is q gmaxFL If there is no intersection, the gas production is considered to be 0; further draw the curve of the intersection gas production and formation pressure. The maximum formation pressure when the gas production is 0 is the formation pressure corresponding to the inflow and outflow curves just tangent to each other, which is also the lower limit of the applicable formation pressure P of the bubble drainage process. rminFD .

[0021] (5) For the plunger gas lift process, the minimum gas production applicable to the given plunger process is q gminPL According to the inflow / outflow curve drawn in step S2, keep the gas production index J unchanged, increase or decrease the formation pressure and draw the inflow curve under the formation pressure condition, such as Figure 6As shown, the inflow curve is tangent to the outflow curve, and the straight line L is obtained by connecting the tangent point and the origin of the coordinate system. Taking the current formation pressure as the reference, the formation pressure is reduced and P rPL1 Equal to the current formation pressure P r , given a series of formation pressures P rPL1 To P rPL , get the inflow curve of gas production changing with bottom hole pressure under different formation pressure conditions, find out the gas production value corresponding to the intersection of the inflow curve and the straight line L under different formation pressure conditions; the gas production at the intersection of the inflow curve and the straight line L under the current formation pressure condition is the maximum gas production q corresponding to the plunger process gmaxPL The formation pressure corresponding to the lower limit of the applicable gas production of the given plunger process is the lower limit of the applicable formation pressure of the plunger process P rminPL .

[0022] (6) Normalize different processes to the inflow / outflow dynamic curve with the optimal process conditions, obtain the operating output of each process under different formation pressure conditions, and then make a unified comparison; obtain the maximum gas production from the inflow / outflow dynamic curve of each process in steps S3 to S5, the lower limit of the formation pressure corresponding to each process, and the minimum gas production after adopting each process; calculate the gas production area S, the formation pressure range Δp r That is, the difference between the current formation pressure and the lower limit of the applicable pressure of each process, and the gas production range Δq g It is the difference between the maximum gas production and the minimum gas production of each process. The gas production decreases under unit formation pressure. , gas production area per unit formation pressure .

[0023] (7) Customize the scoring system and weighting system based on the set comparison process, including optimal string, wellhead pressurization, gas lift, bubble drainage, and plunger; Furthermore, the expression of the comprehensive decision-making model for drainage and gas production is: (twenty one); Where, M is the comprehensive decision-making score of drainage and gas production, points; η is the technical score of the process, points; λ is the economic score of the process, points; k is the weight of the technical score, dimensionless; The first-level indicators are divided into technical part and economic part, with the weight of the technical part being 0.6 and the weight of the economic part being 0.4. The second-level indicators in the technical part are the maximum gas production and the formation pressure range Δp r , gas production decreases under unit formation pressure , gas production area S, gas production area per unit formation pressure , the lower limit of formation pressure, with weights of 0.8, 0.8, 1, 1, 1, 1 respectively. The secondary indicators in the economic part are one-time investment and annual maintenance cost, with weights of 0.5 and 0.5 respectively. Then, according to the parameters obtained in step S6, weighted calculation and normalization are performed to finally obtain a score, and the process with the highest score is defined as the optimal process.

[0024] Compared with the existing method for determining the drainage gas production process, the advantages of the present invention are: (1) By quantitatively analyzing the performance indicators of different processes, the advantages and disadvantages of each process under different production conditions can be intuitively compared.

[0025] (2) Comprehensive consideration of technical and economic factors improves the scientificity and accuracy of process selection.

[0026] (3) The establishment of a weighted scoring system makes the process of process determination more objective and reasonable, which helps to improve the production efficiency and economic benefits of gas wells and reduce production costs.

[0027] The above description is only the research idea of ​​the present invention and is not intended to limit the present invention. Any modifications, equivalent substitutions and improvements made within the spirit and principles of the present invention should be included in the protection scope of the present invention.

Claims

1. A method for determining a gas well drainage gas production process, characterized in that: The following steps are involved: Step S1: Collect the downhole string data and production data of the gas well, including the wellbore structure and well inclination θ , pipe diameter D , gas-liquid ratio GLR , oil pressure p t , wellhead temperature T 0 , natural gas physical parameters, gas production index J , Current formation pressure P r , gas phase relative density γ g and liquid relative density γ L ; Calculate gas phase superficial velocity and liquid phase superficial velocity; Step S2: Draw the inflow / outflow dynamic curve under the current production conditions, use the gas well capacity empirical formula commonly used in engineering to calculate the gas well capacity under each process, and then use Mukherjee-Brill The friction coefficient in the model calculates the wellbore pressure drop. Based on all the data collected in step S1, a series of gas production is given, the corresponding bottom hole flow pressure is calculated, and the outflow curve of the bottom hole flow pressure changing with the gas production is obtained. A series of bottom hole flow pressures are given, and the corresponding gas production is calculated. The inflow curve of the gas production changing with the bottom hole flow pressure is obtained, and it is judged whether the inflow / outflow curves intersect. If there is an intersection, it indicates that stable production is currently possible, otherwise it cannot be stably produced; further, through all the data collected in step S1, the gas well production capacity empirical formula commonly used in engineering is selected to calculate the gas well production capacity, and the Mukherjee-Brill model is used to calculate the wellbore pressure drop; Step S3: Perform performance analysis on the optimal tubing string, wellhead pressurization and gas lift process; Step S4: For the foaming process, a series of gas production and concentration coefficients of foaming agent injection are given. x , calculate the bottom hole flow pressure; then calculate the critical velocity of gas-liquid two-phase liquid film reversal and the critical velocity of foam film reversal by changing the concentration of the foaming agent; Step S5: For the plunger gas lift process, the minimum gas production applicable to the given plunger process is q gminPL , according to the inflow / outflow curve drawn in step S2, maintain the gas production index J Keep the formation pressure constant, increase or decrease the formation pressure and draw the inflow curve under the formation pressure condition, so that the inflow curve is tangent to the outflow curve, and connect the tangent point with the coordinate origin to get a straight line L， Based on the current formation pressure, reduce the formation pressure to P rPL1 Equal to the current formation pressure P r , given a series of formation pressures P rPL1 to P rPL , get the inflow curve of gas production changing with bottom hole pressure under different formation pressure conditions, find out the relationship between the inflow curve and the straight line under different formation pressure conditions L The gas production value corresponding to the intersection of the inflow curve and the straight line under the formation pressure condition L The gas production at the intersection of is the maximum gas production corresponding to the plunger process. q gmaxPL The formation pressure corresponding to the lower limit of the applicable gas production of the given plunger process is the lower limit of the applicable formation pressure of the plunger process. P rminPL ; Step S6: normalize different processes to the inflow / outflow dynamic curve with the optimal process conditions, obtain the operating output of each process under different formation pressure conditions, and then make a unified comparison; Step S7: Customize the scoring system and weighting system according to the set comparison process, including the optimal tubing string, wellhead pressurization, gas lift, bubble drainage, and plunger.

2. A method for determining a gas well drainage and gas production process according to claim 1, characterized in that: In step S6, the maximum gas production, the lower limit of the gas layer pressure corresponding to each process, and the minimum gas production after adopting each process are obtained from the inflow / outflow dynamic curves of each process in steps S3 to S5 by unifying the quantitative parameters; Calculate the gas production area S , gas layer pressure range Δp r It is the difference between the current formation pressure and the lower limit of the applicable pressure of each process. The gas production range Δq g It is the difference between the maximum gas production and the minimum gas production of each process. The gas production decreases under unit gas layer pressure. , gas production area per unit gas layer pressure .

3. A method for determining a gas well drainage and gas production process according to claim 1, characterized in that: In step S7, the scoring system and weighting system are customized, and the expression of the comprehensive decision-making model for drainage and gas production is: In the formula, M Score the comprehensive decision-making for drainage and gas production, points; η Give the craftsmanship a technical score, points; λ Give the process an economic score of 10 points; k is the weight of the technical score, dimensionless; The first-level index is divided into technical part and economic part, with the weight of the technical part being 0.6 and the weight of the economic part being 0.4; The secondary indicators in the technical part are the maximum gas production and the gas layer pressure range. Δp r , gas production decreases under unit gas layer pressure , gas production area S , gas production area per unit gas layer pressure , the lower limit of gas layer pressure, with weights of 0.8, 0.8, 1, 1, 1, 1 respectively. The secondary indicators in the economic part are one-time investment and annual maintenance cost, with weights of 0.5 and 0.5 respectively. Then, according to the parameters obtained in step S6, weighted calculation and normalization are performed to finally obtain a score, and the process with the highest score is defined as the optimal process.

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